Accufacts Inc. Report

Report on Pipeline Safety for Enbridge’s Line 9B Application to NEB

On August 5th, Richard Kuprewicz of Accufacts Inc. submitted his independent analysis regarding pipeline safety in the Line 9B Reversal and Capacity Expansion Project. He analyzed Enbridge’s application and other documents filed to the NEB including their Pipeline Integrity Engineering Assessment (EA). In addition, relevant Information Requests from Intervenors and Enbridge Responses were used to reach some startling conclusions!

The quotes below were taken directly from the 34 page Accufacts Inc. report which can be found HERE. If you have the time, reading the full report is well worth your while! If required, any uncommon terms, abbreviations, or new concepts have been explained in point form below the quotes. Please add your questions / thoughts in the comments section at the bottom of the page.


“Like Line 6B, both Line 9A and Line 9B are 30-inch pipelines exhibiting extensive SCC coincidental with general corrosion pipe wall loss from severely disbonded polyethylene external coating. Such cracking threats are prevalent along the system, appear to pose the greatest threat to pipeline integrity, and are proving very challenging to identify or assess via ILI and engineering assessments.”

  • SCC – Stress Corrosion Cracking – the growth of cracks in a corrosive environment
  • Polyethylene External Coating – Essentially “tape” wrapping the steel pipe
  • Disbond – When the polyethylene tape coating separates from the pipeline steel
  • ILI – In-Line Inspection – Pipeline analyzed from a tool placed inside the pipe

Brief Review of Enbridge Line 9 Project Proposal

“The pipeline was installed in 1975 and is externally coated with polyethylene tape, a tape coating that can seriously disbond or separate from the pipe wall to introduce the threat of SCC in certain environments. This type of coating has a tendency to “tent” near the longitudinal manufacturing seam, generating areas where fields of SCC colonies or “crack fields” in sites of extensive general corrosion that further reduce pipe thickness under the tenting.”

  • Longitudinal Manufacturing Seam – Pipelines segments typically have one horizontal seam. Think of a piece of 8.5 x 11 paper being rolled so that the 11″ edges touch and are secured. The resulting tube has one 11″ longitudinal seam.
  • SCC Colonies / Crack Fields – Pipe sections where numerous small crack areas come together to form a much larger and unstable crack area.
  • Note: Corrosion occurs more often on the outside of a pipeline. If the external corrosion thins the pipe wall and the inside is affected from numerous cracks, the pipeline has an increased risk of failure.

“These extensive SCC sites can also be at risk from another form of environmentally associated cracking, corrosion fatigue cracking, which to the naked eye looks similar to SCC, but is also driven by similar growth mechanisms such as pressure cycling. SCC, corrosion-fatigue, and general corrosion can also interact to accelerate time to failure. Based on the information supplied in the Project’s EA, it is fair to assume that both Line 9A and 9B segments have extensive crack threat sites, such as SCC, similar to those observed in Line 6B across that system.”

  • Corrosion Fatigue Cracking – The disintegration of a material in the form of rust, pitting, or cracking. Corrosion fatigue is typically caused by environmental conditions.
  • Pressure Cycling – Changes in pressure in the pipeline due to varying contents shipped.

Possible Effects of Changing Crude Slate

“Pressure cycling has the ability to seriously affect, vary, and accelerate crack growth rates … Changing crude slates, especially running dilbit, can significantly increase pressure cycles that can accelerate crack growth. The various and changing compositions of dilbit, both the bitumen and/or the diluents, can significantly impact pressure cycles on a pipeline where crack risk is a bona fide threat. Accufacts believes that the movement of dilbit in pipelines at risk of cracking threats presents a higher potential to cause pipeline ruptures if not adequately managed.”

  • Dilbit – Diluted Bitumen – Oil Sands from Alberta diluted with chemicals in order to allow it to flow in a pipeline similar to conventional oil.

Central Findings in NTSB/PHMSA Investigation of Marshall, MI July 25, 2010 Rupture Applicable to Line 9

“Enbridge’s engineering assessments based on historical pressure cycling measurements and the 2005 USCD ILI run data placed Fitness for Service remaining fatigue life of the deepest crack feature in the pipe joint that eventually ruptured, at 21 years. This estimate was well beyond the approximate 4 ½ years to the actual rupture failure that occurred at much lower pressures than the engineering assessment calculated pressure thresholds.”

  • USCD ILI – Ultra Scan Crack Detection In-Line Inspection – General Electric monitoring tool placed inside the pipeline to detect cracks. Note: It is limited to finding cracks greater than or equal to 30mm.
  • Fitness for Service – The pipeline’s ability to operate in a manner that ensures the safety of people and the environment in the area.
  • Fatigue Life – The number of stress cycles that a pipeline sustains before failure occurs.

NTSB Findings in Investigation of Line 6B July 25, 2010 Marshall, MI rupture

“The Line 6B segment ruptured under normal operating pressure due to corrosion fatigue cracks that grew and coalesced from multiple stress corrosion cracks, which had initiated in areas of external corrosion beneath the disbonded polyethylene tape coating.”

“Enbridge’s integrity management program was inadequate because it did not consider the following: a sufficient margin of safety, appropriate wall thickness, tool tolerances, use of a continuous reassessment approach to incorporate lessons learned, the effects of corrosion on crack depth sizing, and accelerated crack growth rates due to corrosion fatigue on corroded pipe with a failed coating.”

“Had Enbridge operated an effective public awareness program, local emergency response agencies would have been better prepared to respond to early indications of the rupture and may have been able to locate the crude oil and notify Enbridge before control center staff tried to start the line.”

“Enbridge’s failure to exercise effective oversight of pipeline integrity and control center operations, implement an effective public awareness program, and implement an adequate postaccident response were organizational failures that resulted in the accident and increased its severity.”

Enbridge’s Response to NTSB IM Concerns

“Concerning the NTSB IM recommendations, it should become fairly clear from comparing the referenced documents that Enbridge has failed to incorporate NTSB recommendations into their integrity management program and this Project’s EA, especially as they relate to the unique and highly challenging threats related to prevalent SCC and associated corrosion, and corrosion fatigue along Line 9. Line 9 contains numerous similar threats associated with polyethylene external coating disbondment and the Enbridge EA fails to adequately demonstrate a prudent evaluation of the SCC/corrosion threat risks on Line 9.”

  • NTSB IM – U.S. National Transportation Safety Board Integrity Management
  • EA – Engineering Assessment

“I see no sufficient detail in the EA that the Enbridge approach has incorporated information to assure that still-developing crack detection ILI technology is being applied in such a manner so as to recognize that this ILI method is still “push technology” and is not reliable, especially when it comes to SCC in corrosion sites associated with this polyethylene tape coating. I use the term “push technology” to mean the application of a new still developing technological approach that has yet to be sufficiently field demonstrated to be highly accurate or reliable, either by the use of the ILI tool or related engineering assessments using the tool’s results.”

“The EA also fails to mention that the 2004/2005/2006 crack runs may be of questionable value based on the Marshall, MI rupture. As a matter of reference, the crack in the Marshall, MI pipeline utilized the same ILI tool crack technology, the same biased software algorithm underreporting SCC depths, and that missed the rupture site on Line 6B that occurred well below MOP. The use of this ILI tool should thus be characterized as still in development, a research experiment. I see no specific indication in the crack section of the Project’s EA that Enbridge has embraced or appropriately incorporated the IM recommendations of the NTSB for the 2004/2005/2006 crack ILI tool runs, and the EA was submitted to the NEB well after the NTSB report on Marshall was adopted.”

  • MOP – Maximum Operating Pressure

Accufacts Conclusions

SCC within corrosion wall loss is prevalent and a high risk along Line 9.

“The EA makes it fairly clear that a primary IM threat prevalent along Line 9 is cracking introduced by the polyethylene disbonded coating tenting in close proximity to the DSAW seam weld. This disbonded coating has permitted significant SCC to occur within general wall loss corrosion in or near the DSAW seam. A CP system is ineffective in dealing with this type of coating disbondment and will not protect against this SCC/corrosion threat, as the protective CP current cannot get to the affected pipe steel that is shielded by this type of coating. SCC by itself in pipelines is somewhat difficult to access but when such SCC is coincident with corrosion wall loss, the engineering assessments can be very difficult to perform with a high degree of confidence and accuracy.”

  • DSAW – Double Submerged Arc Welding technique used along a seam
  • CP – Cathodic Protection – A technique to prevent the corrosion of a metal surface by making that surface the cathode of an electrochemical cell.

“In addition, the Line 9B Project’s EA also fails to make a key point very clear, that the ILI tool during 2004/2005/2006 was non conservative (understated crack depths) for SCC so it is not clear if the EA submitted results have been correctly adjusted for this well-known tool bias, known both to the pig vendor GE and Enbridge, in those specific tool runs. This was the same problem in the 2005 Marshall, MI crack tool run that failed to properly classify and correct for that tool run’s non-conservative bias. Such under indicating can seriously taint Fitness for Service or engineering assessment approaches. This is a recurring problem within Enbridge that has been discovered by Canadian and U.S. investigators after other pipeline crack ruptures.”

  • Pig Vendor GE – General Electric (GE) is the manufacturer of the In-Line Inspection tool used to monitor cracks in the pipeline. These tools are often referred to as “Pigs”.

The ILI cracking took appears to still be a research experiment.

“The ability of the crack detection tool to reliably identify SCC was overstated. Enbridge’s engineering assessments’ inability to apply proper tool tolerance for such developing technology as well as the failure to properly integrate such information with other threats, leads me to conclude that the ILI crack tool runs are more along the line of a research experiment with a high potential for error … If an ILI tool cannot prove reliable and accurate, or its results used appropriately, hydrotesting is still a superior assessment method for many types of threats, especially axially aligned crack threats … Since Enbridge has only recently incorporated changes in the ILI crack tools that were well known by the ILI vendor and Enbridge since 2008 to adjust for SCC misclassification and non-conservative depth bias, I cannot determine if the USCD ILI tool runs of 2012 will be accurate or reliable, or if field verification digs are appropriate for this still developing “push technology”.”

  • Hydrotesting – Hydrostatic Testing – A method in which a pipeline can be tested for strength and leaks. The test involves filling the vessel or pipe system with a liquid, usually water, which may be dyed to aid in visual leak detection, and pressurization of the pipeline to the specified test pressure. Pressure tightness can be tested by shutting off the supply valve and observing whether there is a pressure loss. The location of a leak can be visually identified more easily if the water contains a colorant.

Changing crude slates, especially dilbit, will substantially increase crack growth rates.

“The movement of dilbit, given the substantial changes associated with small variation in composition either in the bitumen or the diluents solvent while meeting tariff requirements, merit exceptional attention on pipelines posing such cracking risks.”

  • Diluents Solvent – Chemicals added to bitumen (oil sands) to allow it to flow.
  • Tariff – Product shipped on a pipeline must meet specifications for safe transport

SCC cracks are most likely to fail as rupture.

“There is a long history in both Canada and the U.S. demonstrating that SCC, when it goes to failure, will usually fail as a rupture, which is one reason why SCC threats command much respect. The EA has not adequately demonstrated that the ILI tool and related engineering assessments have reached the level of confidence that such massive and persuasive SCC threats on Line 9 can be remediated before they reach rupture limits.”

Something appears very wrong with Enbridge’s Line 9B risk assessment.

“Accufacts finds particularly disturbing the statement, ‘Based on this EA, there are presently no features reported by the 2004, 2005 and 2006 crack detection inspections that are predicted to reach critical dimensions until December 2013 based on current reduced operating pressures.” The impression that is being created is that engineering assessment predictions can be reliably estimated for cracks within one year. I must assume that this calculation has not included the NTSB findings and recommendations that clearly indicated that such Enbridge calls needed true ‘conservativeness’. There is just too much uncertainty with cracks coinciding with corrosion to convey such time-to-failure accuracy, especially if an accurate remaining wall thickness is not utilized. Enbridge has also still failed to incorporate the interactive threats associated with corrosion and cracking with real conservatism, such as using a safety factor as recommended by the NTSB.”

Given the many deficiencies uncovered in this application Accufacts places Line 9 at a high risk of rupture failure post reversal.

“I must conclude there is a high risk that Line 9 will rupture from the SCC/corrosion-fatigue/general corrosion interaction attack in the early years following Project implementation: and that Enbridge’s IM approach, which relies on ILI and related engineering assessments, will not prevent rupture under the operating conditions resulting from the implementation of the Project.”

  • IM – Integrity Management

Enbridge’s leak detection will not timely detect rupture.

“Additional NTSB factual reports during the Marshall investigation indicate that Enbridge has a culture of column separation which significantly complicates the reliability of leak detection in the control room to avoid false alarms.”

  • Column Separation – Tiny bubbles of natural gas liquids develop in the fluid. These can mimic a leak on detection systems, and pipeline monitors have trouble telling the difference between true leaks and column separations. Consequently, oil may continue to flow for hours before a leak is detected.

The emergency response plan and response times are not adequate for a high consequence area.

“Enbridge has indicated in several IR responses that travel times for response will be on the order of 1.5 to 4 hours. These response times are completely unworkable for a pipeline located in so many high consequence areas. Enbridge needs to improve equipment staging sites and coordinate/commit appropriate personnel such that response times are significantly reduced for such high consequence areas along Line 9 … Sufficient detail has also not been provided as to the response if dilbit is released. The ERP/Oil Spill Response should distinguish between an ERP which focuses on saving lives and then property, versus oil spill response which focuses on reducing potential oil spill volume, then containment, then recovery. Oil spill response plans also need to address the situations where dilbit can sink such as was clearly shown in the Marshall, MI rupture, and now apparently in the Pegasus Pipeline rupture this past March in Mayflower, AR. Of course oil spill plans still need to address crudes where oil releases will float in water, such as with the lighter Bakken crudes.”

  • ERP – Emergency Response Plan

Recommendations to the NEB

Hydrotesting should be required before Line 9 is reversed.

“Based on the preponderance of information from the NTSB investigation, Accufacts finds that Enbridge has a culture of denial when it comes to the strengths of hydrotesting and a highly distorted over-reliance on ILI inspection on crack detection that has yet to be sufficiently proven to assure pipeline integrity from certain extensive SCC and/or corrosion fatigue cracking threats on Line 9.”

The leak detection approach should be modified to focus on rupture detection in all modes of operation.

“Enbridge should design Line 9 to not operate in slack line operation. This will greatly improve the reliability of the MBS to avoid false alarms during normal operation. The leak detection approach should also be modified to focus on rupture detection during major transients that can be from line packing/inventory impacts associated with compressible hydrocarbons, during startup and shutdown, as well as normal operation. Procedures should be added that assure that such a rupture alarm is never treated as a false alarm. In other words, every rupture alarm should require shutdown, remote valve closure and a pipeline field review to confirm no release occurred. Such modifications should not be expensive to implement.”

Accufacts Final Thoughts

“Accufacts must conclude, given our extensive experience in pipeline risk management and the information provided in this report indicating continuing serious deficiencies still in Enbridge’s IM approach, that without a proper hydrotest there is a high risk the pipeline will rupture in the early years following the Project’s implementation.”

“Accufacts further concludes that Enbridge statements suggesting that such hydrotests can damage a transmission pipeline, or be dangerous to the pipeline, are without technical merit, and appear to be attempts to misinform decision makers and the public.”

“Enbridge has not demonstrated they understand the weaknesses of the Mass Balance System (“MBS”) approach that played a major role in the more than 17 hours it took to recognize that a rupture at Marshall, MI had occurred, and close proper remote operated isolation valves.”

“Based on Accufacts’ extensive experience in pipeline leak detection, control room management regulatory development, and pipeline incident investigation, current estimated oil spill volumes indicated in the Project are most likely significantly understated. In addition, in the event of a release, claimed Enbridge response times in various IR responses of 1.5 to 4 hours for such a high consequence pipeline system as Line 9B are also not adequate or appropriate.”

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